Power-to-gas - Hinicio · Global and long term perspective Rigorous system approach – thinking...
Transcript of Power-to-gas - Hinicio · Global and long term perspective Rigorous system approach – thinking...
COPYRIGHT: HINICIO & LBST
Power - to-gasS h o r t t e r m a n d l o n g t e r m
o p p o r t u n i t i e s t o
l e v e r a g e s y n e r g i e s b e t w e e n t h e e l e c t r i c i t y
a n d t r a n s p o r t s e c t o r s
t h r o u g h p o w e r - t o -
h y d r o g e n
1 8 D e c e m b e r 2 0 1 5
Hinicio
STRATEGY CONSULTANTS
IN SUSTAINABLE ENERGY
AND TRANSPORT
Multidisciplinary
approach and team:
Technology
Market/economics
Policy and regulation
3 offices:
Brussels (HQ)
Paris
Bogota
Clients in more than 15
countries in Europe,
Latin America and Asia
RENEWABLE ENERGY
HYDROGEN AND FUEL CELLS
ENERGY STORAGE ELECTRO-MOBILITY
2
LBST
Independent expert forsustainable energy and mobilityfor over 30 years
Bridging technology, markets,and policy
Renewable energies, fuels,infrastructure
Technology-based strategy
consulting,
System and technology studies,
Sustainability assessment
Global and long term
perspective
Rigorous system approach –
thinking outside the box
Serving international clients
in industry, finance, politics, and
NGOs
3
1. Introduction - Setting the scene
2. Application A : Hydrogen from power-to-gas for use in
refineries
3. Application B : Semi-centralised power-to-hydrogen system
for coupling the electricity and transport sectors
4. Questions
4
Content of the presentation
COPYRIGHT: HINICIO & LBST
Int roduct ion Sett ing the scene
S e c t i o n 1
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More renewables and electrification of transport
are required on the road to 2oC
2oC requires more renewables… … and electrification of transport
• Investment increase from B$270/yr in 2014 to
B$400/yr in 2025.
• Installed capacity growing from 450 GW today
to 3300 GW in 2040.
• Variable renewables increase from 3% of
generation to more than 20% by 2040.
• Sales of EVs exceed 40% of total passenger car
sales worldwide in 2040.
• Sets the scene for providing the needed
emissions reductions after 2040.
Global emissions from power plants
Global emissions
Global light duty vehicle sales
IEA 450 (2oC) scenario
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Additional power generation will be needed
for transport
EU-28 2013 final electricity consumption
~ 2800 TWhe
The required additional power generation capacity depends on the adopted
powertrain technology, but is in any case substantial.
All transport
Road transport
Figures: LBST, Renewables in Transport 2050 – Europe and Germany, 2015
8
Power-to-Gas allows to decarbonise transport while
improving the power system’s operating conditions
More renewable without PtG
= More problems
More renewable with PtG
= Less problems
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Consumption, VRE production an residual load - without PtoG
Residual load VRE production Consumption Mean residual load
Reduced loadfactor
Low minimumload
42 GW
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Power to H2
PtoH2 Mean PtoG
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Consumption, VRE production an residual load - with PtoG
New residual load VRE production Additional VRE
Mean resiudal load Consumption w/o PtoG Consuption with PtoG
52 GW
Power-to-Gas provides systemic benefits and
improved economics for all:
• Improved load factors / less curtailment;
• More predictable operation of dispatchable
capacity.
Power consumption during two days in France in Jan and
Feb 2013. Actual VRE* production on these days multiplied
by 10
Additional consumption of 20 GW on average from H2
mobility
Only half of this is provided by additional VRE
The other half is provided by the existing capacity:
*VRE : variable renewable energy Figures: Hinicio, Compensating VRE intermittency with Power-to-gas
with data [RTE,2015]
Power-to-Gas – PtG :
Production of a high-energy-density gas via water
electrolysis
Power-to-Gas:
Linking renewable electricity and transport
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Scope of the study
Image: LBST.
Mo
bility
Fuels
Electricity
Gas turbine / CCGT
GG
Gas
Fuel cell
Fuel CellFuel Cell
H2
Refuelling stations
Refineries
Methanation
Electricity grid
Renewable electricity
Gas grid
Electrolysis
Ch
emicals
Industry
Hydrogen
Electricity infrastructure
Hydrogen infrastructure
Gas infrastructure
H2 storage
Underground storage
H2 supply chain
Hydrogen applications
Focus of this study
So
urc
e: LB
ST 2
015
10
Power-to-Gas can support balancing at any
time scale and at any point in the T&D system
PtG can close growing gaps between local
production and consumption, reducing the
need to expand the distribution grid, whichcarries most of the burden
2
With a high degree of flexibility andsupported by large amounts of storage, PtG
can support balancing at any time scales,
from supply of primary reserve to seasonal
storage (with underground storage).
1
PtG can be used along with other flexibility
options such as CHP & heat pumps with heat storage, batteries and demand
response.
3
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Power-to-hydrogen can be implemented at
different scales, from distributed to centralised
X0
0 k
m
With H2 useW/o H2 use
X0
km
>X0 MW X MW
Nation-wide HRS network
Region-wide HRS network
centralised
X0 kW
Semi-centralised On-site
So
urc
e: H
inic
io2016
Image: Hinicio
Alkaline PEM
Development stage Industrial since 1920s Early stage commercialization
Maximum capacity
Unit : 3.8 MW/67,7 kg/h
Plant : 100 MW/1900 kg/h
(Zimbabwe)
6 MW/ 120 kg/h
(3 x 2 MW pilot unit)
Current density Up to 0.4 A/cm2 Up to 2 A/cm2
(R&D: 3.2 A cm-2 at 1.8 V at 90oC)
Dynamic response Less than one minute Within seconds
Peak load 100% 200% (30 min)
Turn down 20 – 40 % <10 %
Operating pressure (typical) A few bars Tens of bars
Investment costs 1.1 M€/MW* 1.9 M€/MW*
Operating cost 5 - 7 % 4 %
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Comparing electrolyser technologies
*Includes installation and balance of plant costs
13
Direct injection is the cheapest way to “dump”
hydrogen from excess RE into the gas grid
DIRECT INJECTION• Natural gas specification allows
the blending of hydrogen
• Less costly than methanation
• Maximum injection limit(technical and regulatory).
• There is no business case for direct injection unless regulatory changes are made (FIT…)
METHANATION (Sabatier process) • No maximum injection limit
• Exothermal – potential synergies with CO2 generating process
• Requires a concentrated CO2 source
• More costly than direct injection: no business case without regulatory changes
Advantages Disadvantages
14
Regulation drives the energy transition in
both the power and transport sectors
Topic Sector World EU France Germany
Greenhouse
gases
All sectors< 2oC
(COP21)
2020: -20%
2030: -40%
2040: -60%
2050: -80/-95%
vs. 1990
2030: -40%
2050: -75%
vs. 1990(LTE)
2020: -40%
2030: -55%
2040: -70%
2050: -80/-95%
vs. 1990
Transport
2020: -6% (FQD)
2050: -60%
(COM 2011 144)
2020: -10%2010
(code de l énergie)
2028:-22%2013
2050:-70%2013
(SNBC proj)
2015: -3.5%2010
2017: -4%2010
2020: -6% (BImSchG)
Renewable
energy
All sectors
2020: 20%
2030: 27%
2020: 23%(LTE)
2020: 18%
2030: 30%
2040: 45%
2050: 60%
(Energiekonzept)
Transport2020: 20%(RED)
2020: 10.5%2013
(SNBC proj)
Energy
consumption
All sectors
2020: -20%1990(COM 2011 112)
2020: -7%2005
(SNBC)
2020: -20%
2030: /
2040: /
2050: -50%
Transport
2020: -10%
2030: /
2040: /
2050: -40%
Applications Options BM1 BM2
H2 sales to other markets • H2 fuelling stations
• Industry – H2 refineries
H2 injection into gas grid • Direct
• Methanation
Ancillary services to power grid
• Primary and/or secondary reserve
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Power-to-hydrogen systems can
simultaneously address multiple applications
BM1: Business model 1
• Electrolyser investment and
operation by an independent entity
• Income from hydrogen sales to
market and gas grid and from
provision of ancillary services to the
power grid
BM2: Business model 2
• Electrolyser considered as a part of
the T&D infrastructure
• Costs fully covered by costs-based
grid charges
Business model
assessed
COPYRIGHT: HINICIO & LBST
Appl icat ion AHydrogen f rom
power - to-gas fo r use
in re f iner ies
S e c t i o n 2
There is increasing interest in Germany from refiner’s side
CriteriaEU
Fuel Quality Directive (FQD)
France
Code de l‘énergie
Germany
BImSchG/V
Lifetime 2020 2020 2020
GHG targets
-2 % by 2015
-4 % by 2017
-6 % by 2020
-10% by 2020 -3.5 % by 2015
-4 % by 2017
-6 % by 2020
Responsibility Supplier
Energy tax responsible
entity (usually the fuel
refinery)
Energy tax responsible
entity (usually the refinery)
Options
upstream: Flaring/venting Flaring/venting –
refinery: – Refinery GHG emissions
reduction
–
downstream: Biofuels and alternative
fuels from non-biological
sources
Biofuels, electricity Biofuels
Hydrogen
H2 eligible as transportation
fuel (2015/652/EU, ANNEX I),
not for use in refineries yet
H2 not yet eligible as
transportation fuel.
Reduction of refinery
emissions through use of
low carbon hydrogen is
eligible
H2 not yet eligible; ‘further
renewable fuels’ (e.g. PtG)
and ‘other measures’ are
subject to enforcement of
a legal ordinance (§37d
(2), point 13
Infringement
penalty
Subject to national
implementation, which shall
be ‘effective,
proportionate and
dissuasive’
Not yet defined
(Application decrees to be
published in 2017)
470 €/t CO2eq
Regulatory framework
Fuel greenhouse gas emission reduction
17
18
Refinery landscape Europe
France and Germany are among the
‘top 5’ countries in Europe with regard
to the number of refineries and the
total installed refinery
Germany is the leading refinery
location in Europe, by installed
distillation capacity as well as by the
number of refineries installed
France ranks fourth in Europe by
number and capacity
Source: LBST with data [E3M et al. 2015]
Refineries in France and Germany
Image: LBST with data [MEDDE 2015]
FRANCE GERMANY
68.4 million t/yr capacity 103.4 million t/yr capacity
Image: LBST with data [MWV 2015]
19
The product mix from European refineries is diesel oriented
(31-49% diesel, 13-30% gasoline, 1-12% kerosene – in % of total refinery output)
Marginal differences between French & German refineries’ product mixes only
France and Germany are well within the average of European refineries
Product portfolio of European refineries
Image: [EXERGIA et al. 2015] 20
There is a trade-off between crude oil cost and quality
In Europe, a wide range of crude oil qualities is processed
French and German refiners source rather better qualities
Average crude oil quality [EXERGIA et al. 2015]:
France: 36.0 API gravity, 0.7 wt.-% sulphur
Germany: 37.3 API gravity, 0.5 wt.-% sulphur
Crude oil qualities in European refineries
Image: [EXERGIA et al. 2015] 21
Calculation: Net hydrogen demand = process sources – process uses
Desulphurisation is a sensitive parameter to net hydrogen demand
By tendency,
crude oil quality is further deteriorating increasing sulphur content
demand for heavy fuel fractions is decreasing maritime emission areas
Hydrogen sources and uses in a refinery
Refinery
H2 Sources
Reformer/
Platformer
H2 Uses
Desulphurisation
Hydrotreating
Hydrocracking
Crude oil
H2
H2
Gasoline
Kerosene
Diesel
Other
LBST, 27.10.2015
Net H2 demand
22
Synthetic refinery France
Isomerization
HDS
HDS
Atm. residue: 29.1 Mt
Vaccuum residue
Visbreaker
FCC
Crude
oil
68.4 Mt
0.7% S
36 API
HydroCracker
H2
H2
Atm.distillation
Catalyticreformer
Reformatefractionation
and hydrogenation
H2
Diesel
Heavy naphtha
Light naphtha
Visbreaker
diesel
Diesel
Diesel/Lt.
heating oil
Gasoline
Visbreaker
kerosene
Kerosene
Isomerate
Isomerate
FCC naphtha
Alkylate
iC4/nC4
To naphtha HDS: 0.4 Mt
To kerosene HDS
To diesel HDS
Diesel
GasSep. plant
C4 & lighter
H2
C4 & lighter
C4 & lighter H2
Reformate
FCC naphtha
C3/iC4
C1/C2
Visbreaker
NaphthaLt. naphtha
Lt. naphtha
Heavy naphtha
Refinery France
HDS
H2H2S
C1/C2
H2S
H2S
Vacuumdistillation
HDS
H2H2SVacuum
distillate: 16.9 Mt
C4 & lighter: 0.2 Mt
C4 & lighter
Diesel/
lt. heating oil:
21.5 Mt
Gasoline:
14.9 Mt
Heavy fuel oil: 5.2 Mt
Claus plant
H2S
SHeavy fuel oil/
Feed bitumen plant: 6.9 Mt
C3
Kerosene10.5 Mt
(13.0 Mt)
6.4 Mt
(6.7 Mt)
5.3 Mt
7.9 Mt
0.9 Mt
17.6 Mt
0.4 Mt
LPG: 1.6 Mt Crude naphtha: 7.6 Mt
2.5 Mt
KeroseneJet fuel:
7.8 Mt
AlkylationAlklylate
iC4
1.4 Mt
1.1 Mt
ETBE: 0.1 Mt
Source: LBST refinery model 23
Fra
nc
e [
kt/
yr]
Refinery process H2 demand H2 production Net H2 demand
Hydrocracking 220.3
Vacuum distillate desulfurisation 29.2
Middle distillate desulfurisation 48.9
Naphtha desulfurisation 21.7
FCC cracker 0*
Catalytic reformer 158.9
Total 320.1 158.9 161.3**
Hydrogen demand and production
French & Germany crude oil refineries (kt/yr)
* H2 from FCC plus other gases for heat supply; ** assumed to be supplied by steam-methane reformer (SMR)
Ge
rma
ny
[kt/
yr]
Refinery process H2 demand H2 production Net H2 demand
Hydrocracking 327.2
Vacuum distillate desulfurisation 22.3
Middle distillate desulfurisation 65.1
Naphtha desulfurisation 37.0
FCC cracker 0*
Catalytic reformer 307.7
Total 452.1 307.7 144.4**
24
Life-cycle assessment (LCA)
Pathways for gasoline and diesel supply
Electrolysis Compression & storage
Photovoltaic
Wind power
Extraction Transport Distribution Refuelling station
H2
H2Electricity
Electricity
Crude oil Crude oilGasolineDiesel
GasolineDiesel
Re
new
. ele
ctri
city
Cru
de
oil
Refinery
LBST
, 20
15
-12-
09
NEA
R F
UTU
RE
(GR
EEN
H2)
Extraction Transport Refuelling station
Steam reforming
H2
Natural gas
Extraction & processing Transport
Natural gas
Crude oil Crude oilGasolineDiesel
GasolineDiesel
Nat
ura
l gas
Cru
de
oil
DistributionRefinery
LBST
, 20
15
-12-
09
TOD
AY
(SM
R H
2)
25
26
ScenarioRefinery net H2 demand from 100% green H2
FQD minimum target is -6% GHG emissions by 2020
Greenhouse gas emissions per final fuel
France and Germany [g CO2eq/MJfinal fuel]
94.1 93.4 93.7
0
10
20
30
40
50
60
70
80
90
100
Reference Renwable PtH2 Renwable PtH2
Fossil fuel comparator France Germany
GH
G (
g C
O2
eq
uiv
ale
nt/
MJ f
inal
fue
l) -0.70% -0.45%
27
Refinery GHG emission reduction (gate-to-gate)
France and Germany
To give an impression about the quantities, this is equivalent to annual GHG
emission of C segment cars in the order of
Tangible action for refinery corporate social responsibility (CSR)
France Germany
GHG mitigation of refinery emissions
1.33 Mt CO2eq/a 1.50 Mt CO2eq/a
14.1 % 7.2 %
Gasoline car @ 7.0l/100km 575,000 648,000
Diesel car @ 5.5l/100km 658,000 740,000
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15.58 15.80 15.73
0
2
4
6
8
10
12
14
16
18
H2 from SMR Renwable PtH2 Renwable PtH2
Reference France Germany
Co
sts
(€/G
J fin
al f
ue
l)
Impact on fuel costs:
GHG abatement costs:
Penalties for non-compliance are 470 €/t CO2eq in Germany
Gasoline and diesel production costs
France and Germany [€/GJfinal fuel]
+1.4% +0.9%
+0.8 ct/lDiesel-eq +0.5 ct/lDiesel-eq
LBST
, 20
15
-12
-15
29
331 €/t CO2eq 339 €/t CO2eq
For comparison: 650,000 cars 30,000 €/EV = 19.5 billion €
40 % PV : 60 % wind onshore
France Germany
Net H2 input per crude oil input 0.66 % (LHV) 0.39 % (LHV)
GHG mitigation of refinery emissions1.33 Mt CO2eq/a 1.50 Mt CO2eq/a
14.1 % 7.2 %
H2 demand 4.06 TWhH2/a
122 ktH2/a4.56 TWhH2/a
137 ktH2/a
Required electrolyser capacities 1.58 GWe 1.78 GWe
Electrolyser cost reduction 2025 45 %2015 45 %2015
Cumulated investments electrolysis [€] 1.5 billion € 1.6 billion €
Electricity demand H2 production 6.24 TWhe/a 7.02 TWhe/a
Required RES plant capacities
Wind onshore Photovoltaics
3.14 GWe
1.90 GWe
1.24 GWe
3.73 GWe
2.24 GWe
1.49 GWe
Cumulated investments RES plants 4.4 billion € 5.4 billion €
Cumulated investments RES + electrolysis 5.9 billion € 7.0 billion €
Cumulated investments
France and Germany
30
Example for an average refinery in France in 2020:
8 units of 4 MW wind power plants + 20 MW installed photovoltaics
Scenario installed electrolyser capacities in
French and German refineries
0
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600
800
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1,200
1,400
1,600
1,800
2,000
2015 2020 2025 2030
Inst
alle
d c
apac
ity
(MW
e)
Year
France
Germany
31
Conclusions
Green H2 in refineries is an attractive GHG mitigation option
A portfolio of options will be needed post-2020 at the latest
Introduction of green H2 in an established bulk H2 application
Volume production of H2 reduces electrolyser costs
Electrolysers ‘valley of death’ is bridged by all fuel users
Deployment of electrolysers for refineries is a strategic move entailing long-term benefits for all hydrogen uses.
Recommendations
Establish regulatory grounds for accountability at EU level
Fast-track implementation rather at national level
This study did full-cost analysis to explore the potentials ― next: Refinery specific business case analyses
Regional renewable electricity supply scenarios
Synergies between electricity, refinery, H2 infrastructure
Green hydrogen in refineries
Take-away messages
32
COPYRIGHT: HINICIO & LBST
Appl icat ion BSemi -cent ra l i sed PtG
sys tem for coupl ing
the e lect r ic i ty and
t ranspor t sector s
S e c t i o n 3
34
Novel techno-economic modelling of a semi-
centralised hydrogen system
X0
0 k
m
With transportW/o transport
X0
km
>X0 MW X MW
Nation-wide HRS network
Region-wide HRS network
centralised
X0 kW
Semi-centralised On-site
So
urc
e: H
inic
io2015
Image: Hinicio
35
Main components of a semi-centralised
Power-to-Gas system
Consolidated Business Case
Production
1 MW
Conditioning Storage and
transport
Distribution
CAPEX
H2 cost
€/kg
OPEX
Revenues
H2 production &
conditioning
kgH2
€/kgH2
M€ M€ M€
k€/yr k€/yr k€/yr
€/kgH2 €/kgH2 €/kgH2
- - k€/yr
X
X
X
X
Image: Hinicio
So
urc
e: H
inic
io2015
36
System dimensioning: starting from the
demand
0
50
100
150
200
250
300
350
400
2015 2017 2019 2021 2023 2025
kg/d
Year
Aggregated hydrogen demand (kg/d)
Electrolyser dimensioning and location
• Dimensioning:Hypothetical demand of 325 kg/day requiring a 1 MW of electrolysers capacity
• Location:The electrolyser is located where its makes most sense with regards to interfacing with the power and natural gas grid, operations and logistics.
Production
1 MW
Image& figures: Hinicio
So
urc
e: H
inic
io2015
37
System dimensioning: costs and revenues of
the electolyser and conditioning center
CAPEX1 MW electrolyser including conditioning and trailer filling center and grid injection skid:
• 2015: 2.5 M€
• 2030: 1.2 M€
OPEX Electricity costs
• Spot market price/Energy
purchase price
• Grid charges and other fees
• Grid charge exemption for
electricity used for injection of H2
O&M : 6% CAPEX/year
REVENUES• H2 injection: 90 €/MWh
• Primary/ secondary reserve payments: 18 €/MW/h
Production
Conditioning
Image: Hinicio, H2BCase model
38
System dimensioning: Hydrogen storage and
distribution system
3-step dimensioning method
The HRS storage is sized according to the specific cost of
delivery vs. the specific cost storage capacity (€/kg): delivery
every 3 to 4 days at full capacity.
1
The trailer capacity is chosen in order to have a filling time of
less than one day from the electrolyser.
2
The number of trailers needed in the supply chain is
determined based on time to refill vs total hydrogen
consumption.
3
One 200 kg trailer is sufficient for initial volumes, 3 trailers when full electrolyser capacity is reached.
How to dimension hydrogen logistics and storage?• Size of storage @ HRS• Size of trailers• Number of trailers
39
System dimensioning: costs of logistics and
storage
Storage and
transport
CAPEX• CAPEX trailer * N_trailers
• N_supply-chain fleet = Rotationtime * Demand / Trailer cap.
• CAPEX 200 kg trailer: 125k€
OPEX N_delivery X Cost of delivery
• Delivery cost:
• 45 €/h
• 1.0 €/km
• N_delivery = Consumption /Effective capacity
REVENUES• H2 sales: 8€/kgH2 (delivered from the electrolyser to the hydrogen
refueling stations at 200 bar)
Image: Hinicio, H2BCase model
40
PtG can build on a more favorable electricity
tax regime in France
GRID ACCESS€ 18 / MWh
€ 0 / MWh(electro-intensive)
RENEWABLE ENERGY CHARGE
€ 0.5 / MWh(electro-intensive)
€ 70* / MWh
TOTAL € 19.5 / MWh € 70 / MWh
FRANCE GERMANY
Table: Hinicio & LBST
* Agglomerated average cost including
the concession fees and appropriations
Increasing penetration of low marginal cost generation makes PtG more attractive, in
particular in France
41
For 2020 and 2030, curves are based on marginal costs of production, including CO2 price, and based on projected residual load
power duration curves.
Historical data : 2014 spot market prices for France ; 2013 spot market prices for Germany
• Marginal costs are generally lower in France than inGermany, due to nuclear and increased share ofvariable RE.
• Visible impact of zero marginal cost RE going forward.
-60
-40
-20
0
20
40
60
80
100
120
140
0 1000 2000 3000 4000 5000 6000 7000 8000
€/M
Wh
Hours
Historical and projected marginal-cost-based
price duration curves - GERMANY
Historical (2013) Leitstudie 2011 A (2020) Leitstudie 2011 A (2030)
-60
-40
-20
0
20
40
60
80
100
120
140
0 1000 2000 3000 4000 5000 6000 7000 8000
€/M
Wh
Hours
Historical and projected marginal-cost-based
price duration curves - FRANCE
Historical (2014) Marginal cost based "Nouv Mix 2030"
Figures: Hinicio with data [Leitstudies 2011, RTE 2015, EPEX SPOT 2014, EPEX SPOT 2013]
System operation
• Production
• Conditioning
• Storage
• Logistics
• HRS
Economics and finance
• CAPEX
• OPEX
• Revenues
• Cash flow
• IRR, NPV
• P&L
System sizing optimum
• Production
• Conditioning
• Storage
• Logistics
• HRS
H2BCaseby
42
H2BCase by HINICIO: Optimising and
simulating your hydrogen supply chain
Techno-economic database of
hydrogen technologies
• Production
• Conditioning
• Storage
• Logistics
• HRS
• Vehicles
Energy markets
• Electricity spot price
• Balancing market
• Capacity market
• Natural gas market
• Carbon tax
Local data
• H2 Demand
• Gas grid
• Electricity grid
• Road access
• Distances
All configurations• centralised• Semi-centralised• On-site
Images: Hinicio H2BCase model
43
12 scenarios assessed
ParameterScenario
1 - Ref 2 3 4 5 6 7 8 9 10 11 12
Country France Germany
Year of electrolyser
commissioning2015 2020 2030 2030
Initial/Final H2 Mobility
demand (kg/d)100/325
100/
163
No H2
mobilit
y sales
100/
163
Electricity price
duration curve or cost
France
2014
Germ.
2014
Germ.
2020
Germ.
2030
26% of wind el. CostFrance
100% of
wind
el. cost
France
17% of
wind
el. Cost
Germ.
Grid chargeFrance
2015Germany 2015 rates
CSPE (€/MWh)
Electr.-
int.
0.5
19.5
H2 injection price
(€/MWh)90 (FIT) 55.8
No
inject.
No
inject55.8
Electrolyser capex
(M €/ MW)1,9 0.55 0.55
Electrolyser
efficiency/stack
lifetime
66%/4y75%/
10y
75%/
10y
Table: Hinicio
44
Scenario 1 - Reference - Hypotheses
• H2Mobility market consumes 1/3 of electrolyser
capacity in year 1 (1MW electrolyser – 100
kg/day – 100 FCEV/REX or 4 busses) andincreases to full electrolyser capacity in year 10.
• Electrolyser plant considered to be benefiting
from “electro intensif” regime (low grid / taxfees).
• Available capacity permitting, H2 is produced
for injection into the Gas Grid when marginal
costs of H2 production are lower than Feed-In-
Tariff (assuming €90/ MWh) to achieve increaserevenue streams during market take-off phase of
FCEV.
• No charges applied to the electricity consumed
for producing the hydrogen injected into the gas
gridTable: Hinicio
Representation of Results per Scenario (1)
Revenues:
1. H2Mobility: €8 / kg @ 200
bar @ HRS
2. H2 injected @FIT:
€90/MWh
3. Primary reserve:
€18/MW/h
Figure: Hinicio, H2BCase Model 45
So
urc
e: H
inic
io2016
Representation of Results per Scenario (2)
Variable Costs:
1. H2Mobility: variable
Electricity costs & water
costs
2. H2Mobility: variable cost of
trailer transport (€1/km and
€45/hr)
3. Injection: variable electricity
costs & water costs
Figure: Hinicio, H2BCase Model 46
So
urc
e: H
inic
io2016
Representation of Results per Scenario (3)
Fixed Costs:
1. H2 Mobility: electrolyser
O&M (3% +3% of CAPEX) &
Fixed part of Grid fee &
Trailer & Storage @ HRS O&M
2. Injection: Electrolyser O&M
(3% +3% of CAPEX) & Fixed
part of Grid fee
3. Depreciation of Electrolyser
+ Stack Replacement +
Compressor & Injection Skid
4. Depreciations of Trailer &
Storage @ HRSFigure: Hinicio, H2BCase Model 47
So
urc
e: H
inic
io2016
48
Scenario 1 - Reference - Results
0
200
400
600
800
1.000
1.200
1.400
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
k€/y
Year
1 MW semi-central Power-to-H2 system - Revenues and Costs
(CAPEX depreciated)
Log. annualized capex
Prod annualized capex
Injection fixed costs
Market fixed costs
Injection var.cost
Market var. log. costs
Market var. prod.cost
H2 GoO's
Grid services
Injection sales
Market sales
IRR = 0% (10y)
Payback = 10 years
Injection into the Gas Grid complement revenue streams during “valley of
death” of FCEV market. Its contribution to margin decreases as hydrogen
mobility market takes off.
Figure: Hinicio, H2BCase Model
So
urc
e: H
inic
io2016
49
Injection provides risk coverage against lower
than expected hydrogen sales
S2
: lo
w H
2 M
ob
Ma
rke
t Ta
ke
-O
ff W
ith
in
jec
tio
n
S9
: lo
w H
2 M
ob
Ma
rke
t Ta
ke
-O
ff W
ith
ou
t in
jec
tio
n
0
100
200
300
400
500
600
700
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
k€
/y
Year
Log. annualized capex
Prod annualized capex
Injection fixed costs
Market fixed costs
Injection var.cost
Market var. log. costs
Market var. prod.cost
H2 GoO's
Grid services
Injection sales
Market sales
0
100
200
300
400
500
600
700
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
k€/y
Year
Log. annualized capex
Prod annualized capex
Injection fixed costs
Market fixed costs
Injection var.cost
Market var. log. costs
Market var. prod.cost
H2 GoO's
Grid services
Injection sales
Market sales
IRR = -2% (10y)
Payback = 11 years
IRR = -12%
Payback = 19 years
Figures: Hinicio, H2BCase Model
So
urc
e: H
inic
io2016
So
urc
e: H
inic
io2016
Scenario 3 - Germany 2015 - Hypotheses
Figures and Table: Hinicio, based on data [EPEX SPOT 2013, Germany]50
Parameter1 - Ref 2 3 4 5
Country France Germany
Year of electrolyser
commissioning2015 2020 2030
Initial/Final H2 Mobility
demand (kg/d)100/325
100/
163
Electricity price
duration curve or cost
France
2014
Germ.
2014
Germ.
2020
Germ.
2030
Grid chargeFrance
2015Germany 2015 rates
CSPE (€/MWh)
Electr.-
int.
0.5
H2 injection price
(€/MWh)90 (FIT) 55.8
Electrolyser capex
(M €/ MW)1,9 0.55
Electrolyser
efficiency/stack
lifetime
66%/4y75%/
10y
51
Scenario 3 – Germany 2015 - Results
0
200
400
600
800
1.000
1.200
1.400
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
k€/y
Year
German electricity market conditions : Revenues and Costs
Log. annualized capex
Prod annualized capex
Injection fixed costs
Market fixed costs
Injection var.cost
Market var. log. costs
Market var. prod.cost
H2 GoO's
Grid services
Injection sales
Market sales
IRR = -28% (10y)
Payback = N/A
Figure: Hinicio, H2BCase Model
So
urc
e: H
inic
io2015
Scenario 11 – France 2030 - Hypotheses
• Upfront purchase of the
production of renewable
generation capacity at
projected full cost
• Electrolyser technology of 2030
Table: Hinicio 52
11
2030
100% of
wind
el. cost
France
55.8
0.55
75%/
10y
53
Scenario 11 – France 2030 - Results
IRR = 0% (10y)
Payback = 10 years
0
200
400
600
800
1.000
1.200
1.400
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
k€/y
Year
Log. annualized
capexProd annualized
capexInjection fixed
costsMarket fixed costs
Injection var.cost
Market var. log.
costsMarket var.
prod.costH2 GoO's
Grid services
Injection sales
Figure: Hinicio, H2BCase Model
So
urc
e: H
inic
io2015
54
Based on the marginal cost based priced
duration curve considered for 2030, the Power-to-
Gas application would break even
S5
: G
erm
an
Ele
ctr
icity
Pric
es
&
Ele
ctr
oly
ser
Pe
rfo
rma
nc
e 2
03
0
S3
: G
erm
an
Ele
ctr
icity
pric
es
20
14
IRR = 0% (10y)
Payback = 10 years
IRR = -28%
Payback = N/A
0
200
400
600
800
1.000
1.200
1.400
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
k€
/y
Year
Log. annualized capex
Prod annualized capex
Injection fixed costs
Market fixed costs
Injection var.cost
Market var. log. costs
Market var. prod.cost
H2 GoO's
Grid services
Injection sales
Market sales
Figures: Hinicio, H2BCase Model
So
urc
e: H
inic
io2015
0
200
400
600
800
1.000
1.200
2030 2031 2032 2033 2034 2035 2036 2037 2038 2039
k€
/y
Year
Log. annualized capex
Prod annualized capex
Injection fixed costs
Market fixed costs
Injection var.cost
Market var. log. costs
Market var. prod.cost
H2 GoO's
Grid services
Injection sales
Market sales
So
urc
e: H
inic
io 2
01
5
55
Results of Scenario analysis
Table: Hinicio, H2BCase Model
1
(Ref)
Country France
Year of electrolyser
commissioning2015 2020 2030 2030
100/325
(50+50 /
140+185)
France Germ. Germ.
26% of
wind el.
Cost
100%
of
wind
el. cost
17% of
wind
el. Cost
2014 2014 2030 France France Germ.
Grid chargeFrance
2015
Electr.-int.
0.5
H2 injection price
(€/MWh)
Electrolyser capex
(M €/ MW)
Electrolyser
efficiency/stack
lifet ime
66%/4y 75%/10y75%/10
y
IRR after 10 years 0% -2% -28% 0% -5% N/A -3% -12% 0% 0% 0%
1st Year EBIT > 0 Year 4 Year 2 N/A Year 3 Year 5 N/A year 5 year 13 year 4 Year 5 year 3
Payback Period 10 years 11 years N/A 10 years 12 years N/A 11 years 19 years 9 years10
years
10
years
Alternative 1 to
achieve IRR = 0%
€8.4/Kg H2
Mob
€9.5/Kg H2
Mob
€9.0/Kg
H2 Mob
Primary
Reserve @
45.5/MW/h
€8.5/Kg H2
Mob
€11/kg H2
Mob
Alternative 2 to
achieve IRR = 0%
FIT €109
MWh
FIT @ €190
MWh
FIT @
€121
MWh
FIT @
€133.5
MWh
Primary
Reserve @
€27/MW/h
Primary
Reserve @
€70/MW/h
12Scenario Nbr 2 3 4 5 6 7 8 9 10 11
Germany
Init ial/Final H2
Mobility demand
(kg/d)
100/163
(50+50/(70+
93)
Electricity price
duration curve or
cost
Germ.
2020
No H2
mobility
sales
100/163
Germany 2015 rates
CSPE (€/MWh)
90 (FIT) 55,8 No inject. No inject
19.5
55,8
1,9 0,55 0,55
• Assuming a certain number of favourable regulatory conditions, achieving
economic balance seems feasible for short-term deployments in France;
therefore, with some further support, for instance in the form of investment
subsidies, such deployments could attract private investment.
• The French fee regime applied as assumed above, would be particularly
favourable for Power-to-gas. In contrast, the grid fee regime currently applied
in Germany handicaps Power-to-gas.
• Injection into the natural gas grid can generate two complementary revenue
streams – from sales to the gas grid, and from services to the power grid
performed when hydrogen is produced– which reduces exposure to
uncertainty of revenues from the hydrogen market.
• An economic balance could potentially be achieved in both market
environments and without public financial support by 2030 thanks to
technological improvements.
56
Conclusions
• Create a feed-in tariff for the injection of green or low-carbon hydrogen into
the natural gas grid of a level comparable to that of biomethane in France;
• In France, grant the hyperélectro-intensif status to hydrogen power-to-gas
production;
• In Germany, provide similar tax, EEG appropriation, and grid fee benefits to
hydrogen production by electrolysis as the hyperélectro-intensif status;
• In Europe, further develop sustainability criteria, certification procedures and
accountability of green or low-carbon hydrogen towards EU targets, especially
with regard to the EU Renewable Energies Directive (RED) and the EU Fuel
Quality Directive (FQD);
• Exempt electricity used to produce green or low-carbon hydrogen injected
into the natural gas grid from grid fees and energy taxes;
• Financially support the implementation of supplying hydrogen to fuel cell
electric vehicles.
57
Recommendations
Hinicio and LBST would like to thank Fondation Tuck for supporting this study under its The Future of Energy programme
58
Acknowledgment